This invention relates to the production of a purified gas from a gas mixture containing carbon monoxide and various contaminants including carbon dioxide, hydrogen sulfide and carbonyl sulfide. More specifically, the present invention relates to an integrated process that operates at temperatures about 250° to 550° C. to both remove sulfur compounds and to perform a gas shift reaction to convert carbon monoxide to carbon dioxide which then can be removed from the gas stream.
Numerous methods for removal of acid gas from gas mixtures containing the same are well known in the art and in commercial practice. Included among the known processes for acid gas removal from gaseous streams are those employing physical absorption of CO2 and/or H2S as distinguished from other processes involving chemical reaction. The physical processes are particularly preferred when the feed gas to be treated is available at high pressure and contains relatively large quantities of acid gas constituents and selective separation is desired. Numerous and diverse organic solvents have been suggested or utilized for the desired absorption. Included among the solvents used in known commercial process is methanol, employed in the Rectisol process licensed by Linde Engineering (U.S. Pat. No. 2,863,527); N-methyl-2-pyrrolidone, used in the Lurgi Purisol process (U.S. Pat. No. 3,505,784); propylene carbonate, used in the Fluor Solvent process (U.S. Pat. No. 2,926,751); and dimethyl ethers of polyethylene glycol, used in the UOP Selexol process (U.S. Pat. No. 2,649,166; U.S. Pat. No. 3,362,133). In addition to the many different types of absorption solvents heretofore used or proposed for use in desulfurization and CO2 removal from gas mixtures, a variety of differences in operation techniques and process conditions appear in the patented art and published technical literature. The more widely adopted systems, however, in general, follow an operational sequence that may be characterized as conventional as described below.
In these conventional processes for desulfurization and removal of CO2 from gas mixtures, such as those obtained by partial oxidation of heavy oils or by gasification of coal, the presence of COS in the feed poses difficulties in desulfurization when physical solvent absorption systems are employed. In such conventional processes, the feed gas is charged to an absorption column where it is contacted with the selected physical solvent for absorption of H2S and COS. This desulfurized gas is subjected to a catalytic shift reaction with steam with the CO converted to CO2 and hydrogen is then obtained. The resulting gaseous effluent from the shift converter is treated with a suitable solvent for absorption of CO2 and the resulting gaseous effluent is sent to a methanation section for hydrogenation of residual CO and CO2, obtaining a hydrogen-rich gas product. The spent liquor from the desulfurizing absorber is stripped of contained H2S and COS, providing a product gas from which sulfur values may be recovered in a Claus plant and the lean solvent is recycled for reuse in further treatment of feed gas. The spent solvent from the CO2 absorber is flashed to remove a portion of the CO2, and then stripped of residual CO2 with air or inert gas and the stripped liquid is recycled for reuse in the CO2 absorber column.
The utility requirements for the operation of such conventional processes are comparatively costly. In some of these conventional processes solvent flows required for COS removal in desulfurization results in a dilute Claus gas (typically containing about 11-12 mol-% H2S) which is too dilute for processing in conventional Claus plants for recovery of sulfur values. Accordingly, special expensive Claus plants need to be used, which require high purity oxygen instead of air for burning a part of the H2S to SO2 or a sulfur product recycle oxidation. In addition, such processes require special expensive Claus tail gas units.
Other conventional processes for desulfurization of feed gas mixtures, such as those employing methanol as solvent for the sulfur gas, have been designed to produce a Claus gas of sufficiently high H2S content that can be charged to a conventional Claus gas system. In such Claus sulfur recovery systems, a thermal recovery stage in which the acid gas is burned in a reaction furnace with air or oxygen to combust about one-third of the hydrogen sulfide plus any hydrocarbons and ammonia in the acid gas. The sulfur dioxide from the combustion reacts in the reaction stages with the unconverted hydrogen sulfide to form elemental sulfur. The products of both the combustion and the reaction are cooled in a waste heat boiler and thermal sulfur condenser to recover the sulfur. These systems, however, need to make use of an extra column to concentrate the H2S. Other conventional processes for desulfurization of gas mixtures obtain a Claus feed containing from about 20% to over 50% H2S. The solvents generally employed in such processes, such as, for example, methanol, N-methyl pyrrolidone or dialkyl ethers of polyethylene glycol, are such that the solubility of H2S therein is much greater than that of CO2, while the solubility of COS is intermediate of these. When COS is absent the desulfurization solvent flow rate is set for essentially complete H2S removal and only a small fraction of the CO2 is coabsorbed, so that the desired concentration Claus feed is obtained. When COS is present, however, a substantially higher solvent flow rate is required to obtain complete absorption and desulfurization, with consequent increase in equipment costs and utility requirements. The coabsorption of CO2 is also increased by the higher solvent flow rate and deep flashing of the rich solvent must be utilized to obtain a satisfactory Claus feed containing a required minimum of about 20% H2S. In addition to the foregoing drawbacks, the increased compression requirements for the flash gas add substantially higher capital investment in equipment and higher power costs.
The hereinabove described difficulties and other drawbacks of these earlier known processes for desulfurization of gas mixtures are largely avoided in accordance with the process of the present invention and the economics of the operation are favorably improved, as will hereinafter appear.
Regardless of the carbon source and gasification process, the generated fuel or synthesis gas has to be substantially cleaned before being either burned in a gas turbine or used for chemical synthesis, e.g., methanol, ammonia, urea production, or Fischer-Tropsch synthesis. The clean-up of hot fuel gases avoids the sensible heat loss due to the cooling and subsequent reheating associated with the wet scrubbing techniques referenced above that use either chemical or physical solvents. Ideally, the clean-up of the fuel gas is done at the highest temperature that the fuel gas distribution system can be designed at. This could improve greatly the overall process efficiency, however, there are significant hurdles that need to be overcome before such a hot-fuel gas clean-up system is made commercially available. Only the hot particulate removal systems, i.e., candle filters or sintered metal filters, have been successfully demonstrated commercially for long term applications in a temperature range of 200° to 250° C. at the Nuon's Shell coal gasification plant in The Netherlands, and 370° to 430° C. in the E-Gas coal/coke gasification system at the Wabash River plant. All large scale warm desulfurization demonstration units have failed mostly due to inappropriate sulfur-scavenger materials. Also, with the current state of development of hot gas cleanup systems, all the other contaminants besides the S-compounds and solid particulates can not be removed at equally high temperatures. In addition, due to likely CO2 regulations, all integrated gasification combined cycle (IGCC) gasifiers will need to be equipped with at least one CO-shift reactor, thus requiring cooling the fuel gas to temperatures adequate for the water gas shift catalytic reaction.